The development of shale reservoirs has grown significantly in the past few decades, spurred by evolving technologies in horizontal drilling and hydraulic fracturing. The productivity of shale reservoirs is highly dependent on the design of the hydraulic fracturing treatment. In order to successfully design the treatment, a good understanding of the shale mechanical properties is necessary. Some mechanical properties, such as Young's modulus, can change after the rock has been exposed to the hydraulic fracturing fluids, causing weakening of the rock frame. The weakening of the rock has the potential to increase proppant embedment into the fracture face, resulting in reduced conductivity. This reduction in conductivity can, in turn, determine whether or not production of the reservoir will be economically feasible, as shale rocks are characterized by their ultra-low permeability, and conductivity between the reservoir and wellbore is critical. Thus, shale reservoirs are associated with economic risk; careful engineering practices; and a better understanding of how the mechanical properties of these rocks can change are crucial to reduce this risk. This paper discusses various laboratory tests conducted on shale samples from the Bakken, Barnett, Eagle Ford, and Haynesville formations in order to understand the changes in shale mechanical properties, as they are exposed to fracturing fluids, and how these changes can affect the proppant embedment process. Nanoindentation technology was used to determine changes of Young's modulus with the application of fracturing fluid over time and under high temperature (300 °F) as well as room temperature. Mineralogy, porosity, and total organic content were determined for the various samples to correlate them to any changes of mechanical properties. The last part of the experiments consisted of applying proppants to the shale samples under uniaxial stress and observing embedment using scanning acoustic microscope. The results of this study show that maximum reduction of Young's modulus occurs under high temperature and in samples containing high carbonate contents. This reduction in Young's modulus occurs in "soft" minerals as well as the "hard" rock-forming minerals. This reduction of modulus can cause the effective fracture conductivity to decrease significantly.

"Stress shadowing," where the stress field around an induced hydraulic fracture reorients from its far field directions by up to 90 degrees, is a major factor in designing and executing multiple hydraulically fractured, horizontal well completions. This is especially true as the number of hydraulic fractures increase for a given lateral length. Often the number of fracture stages is determined by well analogues without considering how stress shadows alter fracture properties. In this paper, the main objective is to determine what properties are most important in determining the minimum distance needed between hydraulic fractures to avoid stress interference. A finite element model of a horizontal wellbore with a transverse hydraulic fracture is constructed in order to perform numerical simulations of the stress around the fracture. The model is used to perform sensitivities on various mechanical and reservoir properties to investigate how and why the stress field changed. The simulation results show that the ratio of minimum to maximum horizontal stress is the most important parameter to know in order to determine the optimal fracture spacing. Changes in this ratio show an exponential change in fracture spacing, affecting spacing requirements by up to 81%. Poisson's ratio, Biot's parameter, and net fracture pressure were also important. It can be concluded that fracture spacing cannot be determined by looking only at one or two properties. The fracture spacing must be determined by looking at all the important variables and identifying those that are most variable for the reservoir in question. The sensitivity of the "stress shadow" to various properties is an indication that obtaining good data is key to proper completion design.

Over the last twenty years, Diagnostic Fracture Injection Tests, or DFIT's, have evolved into commonly used techniques that can provide valuable information about the reservoir, as well as hydraulic fracture treatment parameters. Thousands are pumped every year in both conventional and unconventional reservoirs. Unfortunately, many tests that are pumped provide poor or no results due to either problematic data acquisition or incorrect analysis of the acquired data. This paper discusses common issues and mistakes made while acquiring DFIT data. Guidelines on how to avoid these errors and secure the best possible data are provided including data resolution, pump rates, test duration, and fluid selection. Rules of thumb are provided to estimate the time required to reach fracture closure and establish stable reservoir transients for analysis. The last part of the paper addresses potential (and commonly observed) problems in the analysis of the DFIT. These issues can be magnified in tight gas and shale reservoirs due the long data acquisition times and the subtle pressure transients that can occur. Specific issues that are discussed include poor ISIP data from perforation restriction, loss of hydrostatic head, gas entry and the resulting phase segregation, the use of gelled fluids, and errors in after closure analysis.

In cryogenic fracturing, a rock surface exposed to cryogenic fluids undergoes a large thermal gradient, and the resultant local tensile stress overcomes rock strength and initiates fractures. This study investigates the development of cracks generated from the cryogenic treatment of a borehole under no external confining stress on specimens. The experiments were performed on transparent PMMA specimens to observe fracture proliferation around boreholes. Liquid nitrogen was flowed through the boreholes to cool the borehole surface. The results show that initial fracture growth is characterized by abrupt starts and stops, and as the fracture propagates outward, the growth appears more continuous. In an early stage, horizontal/radial fractures and vertical fractures are the defining patterns. Horizontal fractures tend to be separated by a specific exclusion distance (i.e., spacing between cracks). While distinct horizontal/vertical fractures and exclusion distance manifest themselves at an early stage, fractures resulting from fracture interactions and curvatures can develop into complex shapes at later stages. Cryogenic thermal loading induces distinctively curved fractures. The tendency of curvature may prevent greater penetration. An increase in the borehole pressure during liquid nitrogen flow, however, can lessen fracture tortuosity and facilitate radial propagation. A high flow pressure and rate are also advantageous in that they accelerate cooling and fracture propagation.

Hydraulic fracturing is essential for economic production in tight gas and shale gas reservoirs due to their low permeability nature. Slickwater fracturing has been successfully performed in shales and tight gas reservoirs using low viscosity fluid, usually water, with friction reducers. Slickwater fracturing has the advantage of reducing formation damage and generally being less expensive than conventional gel. Predicting which slickwater parameters are important to successful production and which are less important has been an important but unanswered question. This research uses multivariate statistical methods to discover whether production from the Jonah Field, Wyoming, and the Barnett Shale, Texas, can be predicted using slickwater parameters and whether these parameters can provide insight into the design and analysis parameters of the slickwater treatments. Factor, cluster, and multiple regression analysis show that production data from the sampled Barnett Shale and Jonah Field databases group separately from the slickwater parameters. Multiple regression, used to predict the EUR and the cumulative produced water from the slickwater parameters in the Barnett Shale, yielded best adjusted-R²’s of 34.7% and 25.3%, respectively. Multiple regression was also used to predict the EUR from the slickwater parameters in Jonah Field resulting in the best R² of 22.9%. Multiple regression analysis established a relationship with an adjusted R² of 93.0% between the fluid pumped and the fluid recovered from the Barnett Shale treatments. Multiple regression analysis also established that the amount of proppant used for Jonah Field hydraulic fracturing operations was calculated from the total fluid pumped and the net pay. This research provides a methodology to use multivariate statistics to analyze stimulation treatments. Additionally, it opens opportunities for the analysis of different fields with more data using multivariate statistics and can aid in improving designs in an operator's current field or in understanding previous designs in a newly acquired field. Finally, it also demonstrates how "no information" can be valuable in cutting costs on commodities purchased to stimulate a well when no benefit is seen from those additional purchases.